Plans to initiate a pilot steam displacement project with injection into zones as deep as project with injection into zones as deep as 2700' prompted concern for the wellbore heat losses that could be expected. To evaluate this aspect of the pilot design, a computer program was developed. The program and predictive technique were tested by comparing with other published methods and with measured casing temperature data. Agreement of predicted casing temperatures with measured temperature data was within three percent. The program was then used to predict wellbore heat losses under a variety of possible completion designs for steam injection wells in the S1-B zone of the Cat Canyon Field located near Santa Maria, California. These results show that under certain completion conditions, heat losses could be as high as 22 percent. Introduction In 1974, Getty Oil Company began design of a pilot steam displacement project in the S1-B sand of the Cat Canyon Field, Santa Barbara County, California. This zone is a thick, unconsolidated sand which produces nine degree API crude oil through use of cyclic steam stimulation. Wells range to 2700' in depth. In addition, the relatively high injection pressures required (1600 - 2000 psig) result in steam temperatures of approximately 620 degrees F. This combination of deep wells and high steam temperatures prompted concern about the wellbore heat losses which would be sustained. A review of published heat loss calculation methods indicated that very high heat losses could occur under some completion conditions. This review also revealed that each calculation technique had limitations which were of concern. A computer program was then developed which incorporates the best features of the various published techniques, but which is capable of handling more complicated well completion techniques. It is capable of handling cases in which steam quality varies as a function of depth, and also performs a complete heat balance of the steam injection system from steam generator discharge to sand-face. Following program verification, a study of various steam injection completion alternatives was conducted. COMPUTER PROGRAM DESCRIPTION The computer program developed (hereafter called HEATLOSS) calculates wellbore heatlosses based upon conservation of radial heat flow. That is, the steady-state heat flow due to thermal energy lost by the injected steam is assumed to be equal to the transient radial heat flow to the formation. An overall heat transfer coefficient, Uti, is calculated based upon equations for the conductive heat flow through various components of the injector completion and conduction-convection and radiation heat transfer coefficients in the annulus. An iterative procedure is used for this purpose (see the appendix for a detailed discussion of the calculation methods). Having calculated the heat transfer rate (from uti), knowing the steam mass flow rate, and by implicitly determining the steam pressure change, the variation in steam quality is calculated. In addition to the wellbore heat losses, surface steam line heat losses are also considered. These surface lines can be as long as one-half mile, in which case the heat losses can be substantial. The surface lines can be simulated as buried, exposed and not insulated, or exposed and insulated.

We present results of a detailed investigation of the steam/ solvent-coinjection-process mechanism by use of a numerical model with homogeneous reservoir properties and various solvents. We describe condensation of steam/solvent mixture near the chamber boundary. We present a composite picture of the important phenomena occurring in the different regions of the reservoir and their implications for oil recovery. We compare performances of various solvents and explain the reasons for the observed differences. An improved understanding of the process mechanism will help with selecting the best solvent and developing the best operating strategy for a given reservoir. Results indicate that as the temperature drops near the chamber boundary, steam starts condensing first because its mole fraction in the injected steam/solvent mixture (and hence its partial pressure and the corresponding saturation temperature) is much higher than the solvent's. As temperature declines toward the chamber boundary and steam continues to condense, the vapor phase becomes increasingly richer in solvent. At the chamber boundary where the temperature becomes equal to the condensation temperature of both steam and solvent at their respective partial pressures, both condense simultaneously. Thus, contrary to steam-only injection, where condensation occurs at the injected steam temperature, condensation of steam/solvent mixture is accompanied by a reduction in temperature in the condensation zone and the farther regions. However, there is little change in temperature in the central region of the steam chamber. The condensed steam/solvent mixture drains outside the chamber, leading to the formation of a mobile liquid stream (drainage region) where heated oil, condensed solvent, and water flow together to the production well. The condensed solvent mixes with the heated oil and further reduces its viscosity. The additional reduction in viscosity by solvent more than offsets the effect of reduced temperature near the chamber boundary. As the steam chamber expands laterally because of continued injection and as temperature in the hitherto drainage region increases, a part of the condensed solvent mixed with oil evaporates. This lowers the residual oil saturation (ROS) in the steam chamber. Therefore, ultimate oil recovery with the steam/solvent-coinjection process is higher than that in steam-only injection. The higher the solvent concentration in oil at a location, the greater is the reduction in the ROS there. Our explanation is corroborated by the experimental results reported in the literature, which show smaller ROS in the steam chamber after a steam/solvent-coinjection process. A lighter solvent has a lower viscosity, a higher volatility, and a higher molar concentration of solvent in the drainage region. Thus, a lighter solvent causes a greater reduction in the viscosity of the heated oil and also leads to a lower ROS. Therefore, the lightest condensable solvent (butane, under the conditions investigated) provides the most favorable results i...

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractSteam injection EOR began in California forty years ago, and has been highly successful.As a consequence, California's thermal recovery operations represent a leading source of EOR production in the world.The understanding of most early thermal recovery operators was limited to the concept of "heat reduces heavy oil viscosity, and reduced viscosity means more production." Steam injection was attempted in almost any reservoir having viscous oil with little appreciation of other recovery process considerations. Although several early pilot projects were steamfloods, most early applications were cyclic stimulation. During the late 1970's, steamflooding became predominant, and many people considered steamflooding to be a displacement process (hence the term "steam drive'). With this paradigm and high oil prices, there was little impetus to understand efficient use of heat. The predominant philosophy was "If you want more oil, inject more steam." With the later collapse of oil prices, operators returned to review process fundamentals and to determine how to more efficiently operate steam projects. This paper discusses the shift to an override, or gravity drainage, model concept. This helped lead to reduced steam injection and improved thermal efficiency through the use of heat management. This paper discusses the shift to the concept of steam override and gravity drainage as steamflood recovery mechanisms and the subsequent use of heat management practices that improved thermal recovery efficiency.

We present results of a detailed investigation of the steam-solvent co-injection process mechanism using a homogeneous numerical model and three different solvents. The mechanistic model developed in this study describes coupled heat and mass transfer at the chamber boundary and its implications in detail. We present a composite picture of interplay of the process variables, the important phenomena occurring in the different regions of the reservoir and their consequences for oil recovery. The results are corroborated by literature experimental results and field data. The model will help with selecting the best operating strategy for a given reservoir.Results show that the injected steam and solvent vapor condense near the steam chamber boundary. The temperature near the chamber boundary drops because of a reduction in the partial pressure of steam.The condensed steam-solvent mixture drains outside the chamber boundar leading to the formation of a mobile liquid stream where heated oil, water and condensed solvent flow together to the production well. The condensed solvent and water are immiscible and therefore, form separate flow streams. The condensed solvent mixes with the heated oil in the water-oil stream and reduces its viscosity beyond that caused by heating alone, resulting in higher oil production rate. As the steam chamber expands laterally because of continued injection and temperature in the hitherto drainage region increases, part of the condensed solvent mixed with oil evaporates. This lowers the residual oil saturation in the steam chamber. Therefore, ultimate oil recovery with steam-solvent co-injection process is higher than that in steam only injection. The higher the solvent concentration in oil at a location, the greater is the reduction in the residual oil saturation at that location.Thus, steam-solvent co-injection causes a higher oil production rate because of an additional reduction in oil viscosity and a higher ultimate recovery because of a reduction in residual oil saturation. IntroductionSteam Assisted Gravity Drainage (SAGD) has become the technology of choice for exploiting the huge resource base of bitumen. There are more than ten commercial SAGD projects in Canada. The field performance indicates that the process offers high production rate and high ultimate recovery. However, this process requires a large volume of steam injection. The observed steam-oil ratio (SOR) in the field is in the range of 3-5 (Jimenez, 2008). A large usage of steam affects the project economics adversely and also has a detrimental impact on the environment.

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